Hydrocarbons (oil, natural gas, etc.) are obtained from a subterranean geologic formation (i.e., a “reservoir”) by drilling a well that penetrates the hydrocarbon-bearing formation and thus causing a pressure gradient that forces the fluid to flow from the reservoir to the well. Often, a well production is limited by poor permeability either due to naturally tight formations or due to formation damages typically arising from prior well treatment, such as drilling, cleaning, etc.
To increase the net permeability of a reservoir, it is common to perform a well stimulation. A common stimulation technique consists of injecting an acid that reacts with and dissolve a damaged area, or a portion, of the formation, thereby creating alternative flowpaths for producing hydrocarbons to migrate through. This technique known as acidizing (or more generally as matrix stimulation) may eventually be associated with fracturing if the injection rate and pressure is enough to induce the formation of a fracture in the reservoir.
Fluid placement is critical to the success of stimulation treatments. Natural reservoirs are often heterogeneous from a permeability perspective, and fluid will preferentially enter areas of higher permeability in lieu of entering areas where it is most needed. Each additional volume of fluid follows the path of least resistance, and continues to invade in zones that have already been treated. Therefore, it is difficult to place the treating fluids in severely damaged and lower permeability zones. It may be appreciated that stimulation diversion processes and systems have been in use for years to deal with formation heterogeneity. Typically, stimulation diversion processes and systems are comprised of downhole production logging tools (PLT), radioactive tracers with gamma ray detection tools and fiber optic strings measuring distributed temperature. These measurements in the PLT usually have single pressure gauge, single flow meter, gamma ray and temperature gauge. The data from these downhole tools are realtime when an electric cable and/or fiber optic cable is connected inside the coiled tubing string, or in memory mode when the data is collected after the job.
The main problems with conventional stimulation diversion processes and systems are that interpretation of the measurements, whether gathered in realtime or delayed, may be difficult. In most cases, interpretation will come hours after the data is collected. If the telemetry system is not hardwired to the surface, the delay time/data time to the surface also becomes a hardship on timing for interpretation. Another problem with conventional stimulation diversion processes and systems is that the measurements were not designed to provide a qualitative answer to the service that is being performed. One of the many services is flow diversion of fluid into a reservoir section of a well. Another problem with conventional stimulation diversion processes and systems is that they were never designed to run on the end of oilfield tubulars such as coiled tubing.
Other techniques to control and monitor placement of treatment fluids have also been employed. Some mechanical techniques involve for instance the use of ball sealers and packers and of coiled tubing placement to specifically spot the fluid across the zone of interest. Non-mechanical techniques typically make use of gelling agents as diverters for temporary impairing the areas of higher permeability and increasing the proportion of the treating zone that goes into the areas of lower permeability. Of course, a diverter should not itself damage the reservoir and therefore it is important that it can be easily removed following the acid treatment so that the zones of higher permeability remain so.
While existing processes and systems may be suitable for the particular purpose to which they address, they are not as suitable for processes that may use a pre-job design that may be executed and/or evaluated in realtime to ensure treatment fluid is efficiently diverted in a reservoir. Previously known processes' and systems' use of multiple sensors and/or measurements were typically not strategically placed or were ill adapted for flow measurements in coiled tubing and/or drill pipe.
From the above it is evident that there is a need in the art for improvement in monitoring and controlling oilfield fluid diversion systems and methods.